Monitoring Plan XML File Codes...Monitoring Plan XML File Codes Tableof Contents. ... Table 57: Qualification Data Type Code and Descriptions ..... 42 MP XML File Codes May 24, 2012

Monitoring Plan XML File Codes

Table of Contents 1.0 Stacks and Pipes...................................................................................................................... 3

Table 1: Stack Pipe ID Prefixes ................................................................................................ 3 2.0 Monitoring Location Attributes ............................................................................................ 3

Table 2: Material Codes and Description ................................................................................. 3 Table 3: Shape Codes and Descriptions.................................................................................... 3

3.0 Unit Fuel .................................................................................................................................. 3 Table 4: Fuel Codes and Descriptions ...................................................................................... 3 Table 5: Fuel Indicator Codes and Descriptions ....................................................................... 4 Table 6: Demonstration Method to Qualify for Monthly Fuel Sampling for Gross Calorific

Value (GCV) Codes and Descriptions ..................................................................... 4 Table 7: Demonstration Method to Qualify for Daily or Annual Fuel Sampling for %S (ARP)

Codes and Descriptions ............................................................................................ 5 4.0 Unit Controls ........................................................................................................................... 5

Table 8: Parameter Codes and Descriptions ............................................................................. 5 Table 9: Control Codes and Descriptions ................................................................................. 5

5.0 Monitoring Method................................................................................................................. 7 Table 10: Parameter Codes and Descriptions for Monitoring Methods ................................... 7 Table 11: Measured Parameters and Applicable Monitoring Methods .................................... 7 Table 12: Substitute Data Codes and Descriptions................................................................... 9 Table 13: Bypass Approach Codes and Descriptions ............................................................... 9

6.0 Monitoring Systems .............................................................................................................. 10 Table 14: System Type Codes and Descriptions .................................................................... 10 Table 15: System Designation Code and Descriptions ........................................................... 10 Table 16: Fuel Codes and Descriptions .................................................................................. 11

7.0 System Components.............................................................................................................. 12 Table 17: Fuel Codes and Descriptions .................................................................................. 12

8.0 Monitoring System Fuel Flow.............................................................................................. 13 Table 18: Fuel Codes and Descriptions .................................................................................. 13 Table 19: Units of Measure for Maximum Fuel Flow Rate Codes and Descriptions ............. 14 Table 20: Maximum Fuel Flow Rate Source Code ................................................................ 14

9.0 Component Data ................................................................................................................... 14 Table 21: Component Type Codes and Descriptions ............................................................. 14 Table 22: Sample Acquisition Method (SAM) Codes............................................................ 15 Table 23: Basis Codes (BAS) and Descriptions ..................................................................... 16

10.0 Analyzer Range Data.......................................................................................................... 16 Table 24: Analyzer Range Codes and Descriptions ............................................................... 16

11.0 Emissions Formulas ............................................................................................................ 17 Table 25: Parameter Codes and Descriptions for Monitoring Formula.................................. 17 Table 26: F-Factor* Reference Table ..................................................................................... 18 Table 27: SO2 Formula References ........................................................................................ 19 Table 28: SO2 Emission Formulas ......................................................................................... 20 Table 29: NOx Emission Rate Formula Reference Table ...................................................... 21 Table 30: NOx Emission Rate Formulas (lb/mmBtu) ............................................................ 22 Table 31: Moisture Formulas.................................................................................................. 23

May 24, 2012


Table 32: CO2 Formula Reference Table ............................................................................... 23 Table 33: CO2 Concentration and Mass Emission Rate Formulas ......................................... 23 Table 34: Heat Input Formula Reference Table ..................................................................... 26 Table 35: Heat Input Formulas ............................................................................................... 27 Table 36: Apportionment and Summation Formulas .............................................................. 28 Table 37: NOx Mass Emissions Formulas (lbs/hr) ................................................................. 30 Table 38: Miscellaneous Formula Codes ................................................................................ 30 Table 39: Representations for Electronic Reporting ............................................................... 31

12.0 Span Values ......................................................................................................................... 31 Table 40: Component Type Codes and Descriptions for Monitor Span ................................. 31 Table 41: Provision for Calculating Maximum Potential Concentrations (MPC)/ Maximum

Expected Concentration (MEC)/ Maximum Potential Flow Rate (MPF) Codes and Descriptions............................................................................................................ 32

Table 42: Flow Span Calibration Units of Measure ............................................................... 32 13. Rectangular Duct WAF........................................................................................................ 33

Table 43: WAF Method Code and Descriptions..................................................................... 33 14. Unit/Stack/Pipe Load or Operating Level Information .................................................... 33

Table 44: Maximum Load Value Codes and Descriptions ..................................................... 33 15. Monitoring Defaults.............................................................................................................. 34

Table 45: Parameter Codes and Descriptions for Monitoring Default ................................... 34 Table 46: Fuel-Specific Minimum Default Moisture Values for SO2, NOx, CO2, and Heat

Input Rate Calculations .......................................................................................... 35 Table 47: Fuel-Specific Maximum Default Moisture Values for NOx Emission Rate

Calculations ............................................................................................................ 36 Table 48: NOx Emission Factors (lb/mmBtu) for Low Mass Emissions Units ..................... 36 Table 49: SO2 Emission Factors (lb/mmBtu) for Low Mass Emissions Units ...................... 36 Table 50: CO2 Emission Factors (ton/mmBtu) for Low Mass Emissions Units .................... 36 Table 51: Units of Measure Codes by Parameter ................................................................... 37 Table 52: Default Purpose Codes and Descriptions ............................................................... 37 Table 53: Fuel Codes and Descriptions .................................................................................. 37 Table 54: Operating Condition Codes and Descriptions ........................................................ 40 Table 55: Default Source Codes and Descriptions ................................................................. 41

16.0 Qualifications....................................................................................................................... 41 Table 56: Qualification Type Codes and Descriptions ........................................................... 41 Table 57: Qualification Data Type Code and Descriptions .................................................... 42

MP XML File Codes May 24, 2012 Page 2 of 42


1.0 STACKS AND PIPES

TABLE 1: STACK PIPE ID PREFIXES

Prefix Description

CS Common Stack

CP Common Pipe

MS Multiple Stack or Duct

MP Multiple Pipe

2.0 MONITORING LOCATION ATTRIBUTES

TABLE 2: MATERIAL CODES AND DESCRIPTION

Code Description

BRICK Brick and mortar

OTHER Any material other than brick and mortar

TABLE 3: SHAPE CODES AND DESCRIPTIONS

Code Description

RECT Rectangular

ROUND Round

3.0 UNIT FUEL

TABLE 4: FUEL CODES AND DESCRIPTIONS

Code Description

C Coal

CRF Coal Refuse (culm or gob)

DSL Diesel Oil*

LPG Liquefied Petroleum Gas

NNG Natural Gas

OGS Other Gas

OIL Residual Oil



Code Description

OOL Other Oil

OSF Other Solid Fuel

PNG Pipeline Natural Gas (as defined in §72.2)

PRG Process Gas

PRS Process Sludge

PTC Petroleum Coke

R Refuse

TDF Tire Derived Fuel

W Wood

WL Waste Liquid

* Diesel oil is defined in §72.2 as low sulfur fuel oil of grades 1-D or 2-D, as defined by ASTM D-975-91, grades 1-GT or 2-GT, as defined by ASTM D2880-90a, or grades 1 or 2, as defined by ASTM D396-90. By those definitions (specifically ASTM D396-90), kerosene and ultra-low sulfur diesel fuel (ULSD) are considered subsets of diesel oil and therefore should be identified with the code DSL. If a fuel does not qualify as one of these types, the code DSL should not be used.

TABLE 5: FUEL INDICATOR CODES AND DESCRIPTIONS

Code Description

E Emergency

I Ignition (startup)

P Primary

S Backup (secondary)

TABLE 6: DEMONSTRATION METHOD TO QUALIFY FOR MONTHLY FUEL SAMPLING FOR

GROSS CALORIFIC VALUE (GCV) CODES AND DESCRIPTIONS

Code Description

GHS 720 Hours of Data Using Hourly Sampling

GGC 720 Hours of Data Using an Online Gas Chromatograph

GOC 720 Hours of Data Using an Online Calorimeter



TABLE 7: DEMONSTRATION METHOD TO QUALIFY FOR DAILY OR ANNUAL FUEL SAMPLING

FOR %S (ARP) CODES AND DESCRIPTIONS

Code Description

SHS 720 Hours of Data Using Manual Hourly Sampling

SGC 720 Hours of Data Using Online Gas Chromatograph

4.0 UNIT CONTROLS

TABLE 8: PARAMETER CODES AND DESCRIPTIONS

Code Description

NOX Nitrogen Oxides

SO2 Sulfur Dioxide

PART Particulates (opacity)

TABLE 9: CONTROL CODES AND DESCRIPTIONS

Parameter Control Code Description

NOX CM Combustion Modification/Fuel Reburning

DLNB Dry Low NOx Premixed Technology (turbines only)

H2O Water Injection (turbines and cyclone boilers only)

LNB Low NOx Burner Technology (dry bottom wall-fired boilers or process heaters only)

LNBO Low NOx Burner Technology with Overfire Air (dry bottom wall-fired boilers, dry bottom turbo-fired boilers, or process heaters only)

LNC1 Low NOx Burner Technology with Close-Coupled Overfire Air (OFA) (tangentially fired units only)

LNC2 Low NOx Burner Technology with Separated OFA (tangentially fired units only)

LNC3 Low NOx Burner Technology with Close-Coupled and Separated OFA (tangentially fired units only)

LNCB Low NOx Burner Technology for Cell Burners

NH3 Ammonia Injection

O Other

OFA Overfire Air

SCR Selective Catalytic Reduction



Parameter Control Code Description

SNCR Selective Non-Catalytic Reduction

STM Steam Injection

SO2 DA Dual Alkali

DL Dry Lime FGD

FBL Fluidized Bed Limestone Injection

MO Magnesium Oxide

O Other

SB Sodium Based

WL Wet Lime FGD

WLS Wet Limestone

PART B Baghouse(s)

ESP Electrostatic Precipitator

HESP Hybrid Electrostatic Precipitator

WESP Wet Electrostatic Precipitator

WS Wet Scrubber

O Other

C Cyclone



5.0 MONITORING METHOD

TABLE 10: PARAMETER CODES AND DESCRIPTIONS FOR MONITORING METHODS

Code Description (Units)

CO2 CO2 Mass Emissions Rate (tons/hr)

CO2M CO2 Mass Emissions (tons)

H2O Moisture (%H2O)

HI Heat Input Rate (mmBtu/hr)

HIT Heat Input Total (mmBtu) (LME only)

NOX NOx Mass Emissions Rate (lb/hr)

NOXM NOx Mass Emissions (lb) (LME only)

NOXR NOx Emissions Rate (lb/mmBtu)

OP Opacity (percent)

SO2 SO2 Mass Emissions Rate (lb/hr)

SO2M SO2 Mass Emissions (lb) (LME only)

TABLE 11: MEASURED PARAMETERS AND APPLICABLE MONITORING METHODS

Parameter Method Code Description

CO2 AD Appendix D Gas and/or Oil Flow System(s) (Formula G-4)

AMS Alternative Monitoring System*

CEM CO2 Continuous Emission Monitor

CO2M FSA Fuel Sampling and Analysis (Formula G-1)

LME Low Mass Emissions (§75.19)

H2O MMS Continuous Moisture Sensor

MDF Moisture Default

MTB Moisture Lookup Table

MWD H2O System with Wet and Dry O2 Analyzers




HI AD Appendix D Gas and/or Oil Flow System(s)

ADCALC Appendix D Gas and/or Oil Flow System at location (unit) and different Oil or Gas Measured at Common Pipe. (Heat Input at the unit is determined by adding the appropriate value apportioned from the Common Pipe to the unit value)


CALC Calculated from Values Measured at Other Locations. (Used for three situations: (1) this is the method at a unit when heat input is determined at a common stack or common pipe and then apportioned to the constituent units; or (2) this is the method at a unit when heat input is determined at multiple stacks and then summed to the unit; or (3) this is the method at a common stack if heat input is determined at the units and then summed to the common stack in order to calculate NOx mass)

CEM Flow and O2 or CO2 Continuous Emission Monitors

EXP Exempt from Heat Input monitoring

HIT LTFF Long-Term Fuel Flow (Low Mass Emissions -- §75.19)

LTFCALC Long-Term Fuel Flow (Low Mass Emissions -- §75.19) at the unit and different Long Term Fuel Flow at the common pipe. (Heat Input at the unit is determined by adding the appropriate value apportioned from the Common Pipe to the unit value)

MHHI Maximum Rated Hourly Heat Input (Low Mass Emissions)

CALC Calculated from values measured at the common pipe. (This is the method at a unit when heat input is determined at a common pipe and apportioned to the constituent units)

NOX AMS Alternative Monitoring System*

CEM NOx Concentration times Stack Flow rate

CEMNOXR NOx Concentration times Stack Flow rate and NOx Emission Rate times Heat Input Rate (one as a primary method and the other as secondary). This method is not permitted after December 31, 2007

NOXR NOx Emission Rate times Heat Input Rate

NOXM LME Low Mass Emissions (§75.19)

NOXR AMS Alternative Monitoring System*

AE Appendix E

CEM NOx Emission Rate CEMS

PEM Predictive Emissions Monitoring System (as approved by petition)

OP COM Continuous Opacity or Particulate Matter Monitor

EXP Exempted




SO2 AD Appendix D Gas and/or Oil Flow System(s)


CEM SO2 Continuous Emission Monitor

CEMF23 SO2 Continuous Emission Monitor, and Use of F-23 Equation during hours when only very low sulfur fuel is burned per §§75.11(e) and 75.11(e)(4)

F23 Use of F-23 Equation if only very low sulfur fuel is burned per §§75.11(e) and 75.11(e)(4)

SO2M LME Low Mass Emissions (§75.19)

* Use of this method requires EPA approval

TABLE 12: SUBSTITUTE DATA CODES AND DESCRIPTIONS

Code Description Appropriate For Parameter Codes

SPTS Standard Part 75 NOXR, NOX, SO2, CO2, H2O, and HI

FSP75 Fuel-Specific Part 75 NOXR, NOX, SO2, CO2, H2O, and HI

FSP75C Fuel-Specific Part 75 with separate co-fired database

NOXR, NOX, SO2, CO2, H2O, and HI

OZN75 Ozone vs. Non-Ozone Season NOX, NOXR

NLB Non-Load Based NOXR, NOX, and HI

NLBOP Non-Load Based with Operational Bins NOXR, NOX, and HI

REV75 Reverse of Standard Part 75 H2O

MHHI Maximum Rated Hourly Heat Input Rate for LME Units using Long Term Fuel Flow methodology

HIT

TABLE 13: BYPASS APPROACH CODES AND DESCRIPTIONS

Code Description

BYMAX MPC or MER for Highest Emitting Fuel

BYMAXFS Fuel-Specific MPC or MER



6.0 MONITORING SYSTEMS

TABLE 14: SYSTEM TYPE CODES AND DESCRIPTIONS

Code Description

CO2 CO2 Concentration System

FLOW Stack Flow System

GAS Gas Fuel Flow System

H2O Moisture System that uses wet and dry O2 analyzers

H2OM Moisture System that uses a continuous moisture sensor

H2OT Moisture System that uses a temperature sensor and a table of lookup values

LTGS Long Term Gas Fuel Flow System (LME)

LTOL Long Term Oil Fuel Flow System (LME)

NOX NOx Emission Rate System

NOXE Appendix E NOx System

NOXC NOx Concentration System

NOXP NOx Emission Rate PEMS System

O2 O2 Concentration System

OILV Volumetric Oil Fuel Flow System

OILM Mass of Oil Fuel Flow System

OP Opacity (ARP only)

PM Particulate Matter Monitoring System

SO2 SO2 Concentration System

TABLE 15: SYSTEM DESIGNATION CODE AND DESCRIPTIONS

Code Description

P Primary.

PB Primary Bypass. A primary bypass (PB) describes a monitoring system located on a bypass stack before a heat recovery steam generator (HRSG).1

RB Redundant Backup. A redundant backup (RB) monitoring system is operated and maintained by meeting all of the same program QA/QC requirements as a primary system.

B Non-Redundant Backup. A non-redundant backup system (B) is a "cold" backup or portable monitoring system, having its own probe, sample interface, and analytical components.

DB Data Backup. A data backup system is comprised of the analytical components



Code Description

contained in the primary monitoring system (or in a redundant backup system), but includes a backup DAHS component.

RM Reference Method Backup. A reference method (RM) monitoring system is a monitoring system that is operated as a reference method pursuant to the requirements of Appendix A to Part 60.

CI2 Certified Monitoring System at the Inlet to an Emission Control Device.

1 "P" used for the monitoring system located on the main HRSG stack.

2 "CI" only used for units with add-on SO2 or NOx emission controls. Specifically, the use of a "CI" monitoring system is limited to the following circumstances:

● If the unit has an exhaust configuration consisting of a monitored main stack and an unmonitored bypass stack, and the source elects to report SO2 data from a certified monitoring system located at the control device inlet (in lieu of reporting maximum potential concentration) during hours in which the flue gases are routed through the bypass stack; or

● If the outlet SO2 or NOx monitor is unavailable and proper operation of the add-on emission controls is not verified, and the source elects to report data from a certified SO2 or NOx monitor at the control device inlet in lieu of reporting MPC or MER values. However, note that for the purposes of reporting NOx emission rate, this option may only be used if the inlet NOx monitor is paired with a diluent monitor and represented as a NOx-diluent monitoring system in the Component record.


Code Description

BFG Blast Furnace Gas

BUT Butane Gas

CDG Coal Derived Gas

COG Coke Oven Gas

DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas

LPG Liquefied Petroleum Gas (if measured as a gas)

MIX Mixture of oil/gas fuel types (for NOXE system for co-fired curve only)

NFS Non-Fuel-Specific for CEM (including H2O) and Opacity Systems

NNG Natural Gas

OGS Other Gas

OIL Residual Oil

OOL Other Oil



Code Description

PDG Producer Gas


PRG Process Gas

PRP Propane Gas

RFG Refinery Gas

SRG Unrefined Sour Gas

7.0 SYSTEM COMPONENTS


Code Description


BUT Butane Gas


COG Coke Oven Gas

DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas




NNG Natural Gas

OGS Other Gas

OIL Residual Oil

OOL Other Oil

PDG Producer Gas


PRG Process Gas

PRP Propane Gas

RFG Refinery Gas




8.0 MONITORING SYSTEM FUEL FLOW


Code Description


BUT Butane Gas


COG Coke Oven Gas

DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas




NNG Natural Gas

OGS Other Gas

OIL Residual Oil

OOL Other Oil

PDG Producer Gas


PRG Process Gas

PRP Propane Gas

RFG Refinery Gas




TABLE 19: UNITS OF MEASURE FOR MAXIMUM FUEL FLOW RATE CODES AND DESCRIPTIONS

Parameter Code Description

Volumetric Flow of Oil SCFH Standard cubic feet per hour

GALHR Gallons per hour

BBLHR Barrels per hour

M3HR Cubic meters per hour

Mass of Oil LBHR Pounds per hour

Gas Flow HSCF 100 standard cubic feet per hour

TABLE 20: MAXIMUM FUEL FLOW RATE SOURCE CODE

Code Description

URV Maximum rate based on the upper range value of the unit

UMX Maximum rate based on the rate at which the unit can combust fuel

9.0 COMPONENT DATA

TABLE 21: COMPONENT TYPE CODES AND DESCRIPTIONS

Code Description

BGFF Billing Gas Fuel Flowmeter

BOFF Billing Oil Fuel Flowmeter

CALR Calorimeter

CO2 Carbon Dioxide Concentration Analyzer

DAHS Data Acquisition and Handling System

DL Data Logger or Recorder

DP Differential Pressure Transmitter/Transducer

FLC Flow Computer

FLOW Stack Flow Monitor

GCH Gas Chromatograph

GFFM Gas Fuel Flowmeter

H2O Percent Moisture (Continuous Moisture System only)



Code Description

NOX Nitrogen Oxide Concentration Analyzer

O2 Oxygen Concentration Analyzer

OFFM Oil Fuel Flowmeter

OP Opacity Measurement

PLC Programmable Logic Controller

PM Particulate Matter Measurement

PRB Probe

PRES Pressure Transmitter/Transducer

SO2 Sulfur Dioxide Concentration Analyzer

TANK Oil Supply Tank

TEMP Temperature Transmitter/Transducer

TABLE 22: SAMPLE ACQUISITION METHOD (SAM) CODES

Component Code Description

For CEMS DIL Dilution

DIN Dilution In-Stack

DOD Dry Out-of-Stack Dilution

DOU Dilution Out-of-Stack

EXT Dry Extractive

IS In Situ

ISP Point/Path in Situ

ISC Cross Stack in Situ

O Other

WXT Wet Extractive

For Volumetric Stack Flow Monitor DP Differential Pressure

O Other

T Thermal

U Ultrasonic



For Fuel Flowmeter Types COR Coriolis

DP Differential Pressure (e.g., Annubar)

NOZ Nozzle

O Other

ORF Orifice

PDP Positive Displacement

T Thermal Mass Flowmeter

TUR Turbine

U Ultrasonic

VCON V-Cone

VEN Venturi

VTX Vortex

TABLE 23: BASIS CODES (BAS) AND DESCRIPTIONS

Code Description

W Wet

D Dry

B Both wet and dry (O2 only)

10.0 ANALYZER RANGE DATA

TABLE 24: ANALYZER RANGE CODES AND DESCRIPTIONS

Code Description

H High Range

L Low Range

A Auto Ranging



11.0 EMISSIONS FORMULAS

TABLE 25: PARAMETER CODES AND DESCRIPTIONS FOR MONITORING FORMULA

Code Description

CO2 CO2 Hourly Mass Emission Rate (tons/hr)

CO2C CO2 Concentration (%CO2)

CO2M CO2 Daily Mass (tons)

FC F-Factor Carbon-Based

FD F-Factor Dry-Basis

FGAS Gas Hourly Flow Rate (hscf)

FLOW Net Stack Gas Volumetric Flow Rate

FOIL Net Oil Flow Rate to Unit/Pipe

FW F-Factor Wet-Basis

H2O Moisture (%H2O)

HI Heat Input Rate (mmBtu/hr)

HIT Heat Input Total (mmBtu)

NOX NOx Hourly Mass Emission Rate (lb/hr)

NOXR NOx Emission Rate (lb/mmBtu)

OILM Oil Mass Flow Rate (lb/hr)

SO2 SO2 Hourly Mass Emission Rate (lb/hr)

SO2R SO2 Emission Rate (lb/mmBtu) When Equation D-1h Is Used



TABLE 26: F-FACTOR* REFERENCE TABLE

Option 1: Fuel-Based Constants

Fuel

F-Factor (dscf/

mmBtu)

Fc-Factor (scf CO2/ mmBtu)

Fw-Factor (wscf/mmBtu)

Coal Anthracite 10,100 1,970 10,540

Bituminous 9,780 1,800 10,640

Sub-bituminous 9,820 1,840 ------

Lignite 9,860 1,910 11,950

Petroleum Coke 9,830 1,850 ------

Tire-Derived Fuel 10,260 1,800 ------

Gas Natural Gas 8,710 1,040 10,610

Propane 8,710 1,190 10,200

Butane 8,710 1,250 10,390

Oil Oil 9,190 1,420 10,320

Waste Municipal Solid Waste 9,570 1,820 ------

Wood Bark 9,600 1,920 ------

Wood Residue 9,240 1,830 ------

Option 2: Calculated F-Factors

Code Para-meter Formula Where:

F-7A FD x 10GCV

- 0.46(%O)+ 0.14(%N)+ 0.57(%S)+ 1.53(%C)3.64(%H)=F 6 F = Dry-basis F-factor

(dscf/mmBtu) Fc = Carbon-based F-factor (scf

CO2/mmBtu) Fw = Wet-basis F-factor

(wscf/mmBtu) %H,%N, = Content of element, percent %S, %C, by weight, as determined %O,%H2O on the same basis as the

gross calorific value by ultimate analysis of the fuel combusted using ASTM D3176-89 for solid fuels, ASTM D1945-91 or ASTM D1946-90 for gaseous fuels, as applicable

GCV = Gross calorific value (Btu/lb) of fuel combusted determined by ASTM D2015-91 for solid and liquid fuels or ASTM

F-7B FC

GCV

x (%C)321 x 10=F 3

c

19-14 FW

x 10 GCV

0.46(%O)+0.21(% H O)5.57(%H)+1.53(%C)+0.57(%S)+0.14(%N)-=F 6

w

2 w



D1826-88 for gaseous fuels, as applicable

GCVw = Calorific value (Btu/lb) of fuel combusted, wet basis

F-8** FD, FC, or

FW X FF = ii

n

i=1

F = Dry-basis F-factor (dscf/mmBtu)

Fc = Carbon-based F-factor (scf CO2/mmBtu)

n = Number of fuels being combusted

Fi,(Fc)i, = Applicable F, Fc, or Fw

(Fw)i factor for each fuel type Xi = Fraction of total heat input

derived from each type of fossil fuel

)X ( F=F ici

n

i=1 c

)X ( F=F iwi

n

i=1 w

* F-factor is the ratio of the gas volume of all the products of combustion (less water) to the heat content of the fuel. Fc-factor is the ratio of the gas volume of the CO2 generated to the heat content of the fuel (see Part 75, Appendix F, Section 3.3). F-factor is the ratio of the quantity of wet effluent gas generated by the combustion to the heat content of the fuel including free water in the fuel.

** This formula is used for affected units that combust combinations of fossil fuels or fossil fuels and wood residue. For affected units that combust a combination of fossil and non-fossil fuels, the selected F-factor must receive state or EPA approval.

TABLE 27: SO2 FORMULA REFERENCES

Usage Moisture Basis Appropriate Hourly Formulas

(Part 75, Appendices D&F)

SO2 CEMS WET F-1

DRY F-2

Default SO2 emission rate when low sulfur fuels are burned (e.g., natural gas)

F-23 (and D-1H)

Oil Fuel Flowmeter D-2

Gas Fuel Flowmeter D-4 or D-5 (and D-1H)

Overall values for multiple fuel flowmeter systems

D-12



TABLE 28: SO2 EMISSION FORMULAS

Code Parameters Formula Where:

F-1 SO2 x Q= K x CE hhh Eh = K = Chp =

Ch =

Qh and = Qhs

%H2O =

Hourly SO2 mass emission rate (lb/hr) 1.660 x 10-7 for SO2 ((lb/scf)/ppm) Hourly average SO2 concentration (ppm (dry)) Hourly average SO2 concentration (ppm (stack moisture basis)) Hourly average volumetric flow rate (scfh (stack moisture basis)) Hourly average stack moisture content (percent by volume)

F-2 SO2

100

% H O100 -xx Q= K x CE

2 hshph

D-1H SO2R

GCV Sxx 10

7000

2.0 =ER total6

ER =

Stotal =

GCV =

Default SO2 emission rate for natural gas (or "other" gaseous fuel) combustion (lb/mmBtu) Total sulfur content of gaseous fuel (grains/100 scf) Gross calorific value of the gas (Btu/100 scf)

2.0 = 7000 =

106 =

Ratio of lb SO2/lb S Conversion of grains/100 scf to lb/ 100 scf Conversion of Btu to mmBtu

D-2 SO2

100.0

% Sx= 2.0 x OILSO 2 oil

rate-oilrate

SO2rate-oil =

OILrate =

%Soil =

2.0 =

Hourly mass emission rate of SO2

emitted from combustion of oil (lb/hr) Mass rate of oil consumed per hour during combustion (lb/hr) Percent sulfur by weight measured in oil sample Ratio of lb SO2 to lb S

D-4 SO2

x Sx GAS=SO 2 gasraterate (2.0 / 7000)

SO2rate =

GASrate =

Sgas =

2.0 = 7000 =

Hourly mass rate of SO2 from combustion of gaseous fuel (lb/hr) Hourly metered flow rate of gaseous fuel combusted (100 scf/hr) Sulfur content of gaseous fuel (grains/100 scf) Ratio of lb SO2/lb S Conversion of grains/100 scf to lb/ 100 scf

D-5 SO2

ER x HI=SO 2 raterate

SO2rate =

ER =

HIrate =

Hourly mass emission rate of SO2 from combustion of gaseous fuel (lb/hr) SO2 emission rate from Appendix D, Section 2.3.1.1 or Appendix D, Section 2.3.2.1.1 to Part 75 (lb/mmBtu) Hourly heat input rate of a gaseous fuel, calculated using procedures in Appendix D, Section 3.4.1 to Part 75 (mmBtu/hr)



Code Parameters Formula Where:

F-23 SO2

HIxER=E h

Eh

ER

HI

= =

=

Hourly SO2 mass emission rate (lb/hr) Applicable SO2 default emission rate from Appendix D, Section 2.3.1.1, or Appendix D, Section 2.3.2.1.1 to Part 75 (lb/mmBtu) Hourly heat input rate, determined using a certified flow monitor and diluent monitor, according to Appendix F, Section 5.2 (mmBtu/hr)

D-12* SO2

u

irate-i

- fuelsall rate

t

tSO

=SO 2

2

SO2rate

SO2rate-i

ti

tu

=

=

=

=

Hourly mass emission rate of SO2 from combustion of all fuels (lb/hr) SO2 mass emission rate for each type of gas or oil fuel combusted during the hour (lb/hr) Time each gas or oil fuel was combusted for the hour (fraction of an hour) Operating time of the unit

* This equation is a modified form of Equation D-12 as described in Appendix D, Section 3.5.1, and must be used when reporting in XML format.

TABLE 29: NOX EMISSION RATE FORMULA REFERENCE TABLE

Usage

Moisture Basis Appropriate Hourly

FormulasNOx CO2 O2

NOx CEMS (CO2 Diluent) DRY DRY 19-6

DRY WET 19-9

WET DRY 19-8

WET WET 19-7 or F-6

NOx CEMS (O2 Diluent) DRY DRY 19-1 or F-5

DRY WET 19-5 or 19-5D

WET DRY 19-4

WET WET 19-2, 19-3, or 19-3D

Overall Value from Multiple Appendix E Systems

E-2



TABLE 30: NOX EMISSION RATE FORMULAS (LB/MMBTU)

Code Parameter Formula Where:

19-1 (F-5)

NOXR

20.9-%O

20.9 xx FK x C=E

2

dd

d

Formulas should be multiplied by the conversion factor "K" (if Cd or Cw is in ppm)

FROM TO MULTIPLY BY "K" ppm NOx lb/scf K = 1.194 X 10-7

E = Emission rate (lb/mmBtu) Cd = Pollutant concentration (ppm, dry

basis) Cw = (Pollutant concentration ppm, wet

basis) Fd = Dry-basis F-factor (dscf/mmBtu) Fc = Carbon-based F-factor (scf

CO2/mmBtu) Fw = Wet-basis F-factor (wscf/mmBtu) Bwa = Moisture fraction of ambient air

(default value 0.027) %H2O = Moisture content of effluent gas O2d = Oxygen diluent concentration

(percent of effluent gas, dry basis) O2w = Oxygen diluent concentration

(percent of effluent gas, wet basis) O2def = Default diluent cap O2 value (14.0

percent for boilers, 19.0 percent for combustion turbines)

CO2d = Carbon dioxide diluent concentration (percent of effluent gas, dry basis)

CO2w = Carbon dioxide diluent concentration (percent of effluent gas, wet basis)

Ef = NOx emission rate for the unit for a given fuel at heat input rate HIf, lb/mmBtu

HIf = Heat input rate for the hour for a given fuel, during the fuel usage time, as determined using Equation F-19 or F-20 in Section 5.5 of Appendix F to this part, mmBtu/hr

HT = Total heat input for all fuels for the hour from Equation E-1

tf = Fuel usage time for each fuel (rounded to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator))

19-2 NOXR

%O-)20.9(1- B

20.9 xx FK x C=E

2wa ww

w

19-3* NOXR

-%O100 -% H O100

20.9 x

20.9 xx F= K x CE

2 2

dw

w

19-3D* NOXR

100 100-%H O

x-%O100 -%H O100

20.9x

20.9E=K xC x F x

2 2

2 dw

def

19-4* NOXR

)%O-(20.9

20.9 x

% H O) 100-(100

x F )( C= K xE 22

dw

d

19-5* NOXR

100 % H O100 -

% O20.9 -

x F20.9 x K x C=E 2

2

dd

w

19-5D NOXR

%O20.9 -

20.9 xx F= K x CE

2

dd

def

19-6 NOXR

%CO

100 xx FK x C=E

2

cd

d

19-7 (F-6)

NOXR

%CO

100 xx FK x C=E

2

cw

w

19-8* NOXR

%CO

100 x

%H O) 100(100-

x F )(CK x=E 22

cw

d

19-9* NOXR

% CO

100 xx F

100

% H O100 -x= K x CE

2

c 2

d

w

E-2 NOXR

H

)tx HI( E =E

T

fff

all fuels

f =1 h

* Note that [(100 - %H2O/100] may also represented as (1 - Bws), where Bws is the proportion by volume of water vapor in the stack gas stream.



TABLE 31: MOISTURE FORMULAS


F-31 H2O x 100

O

)O-( O% H O=

2

22 2

d

wd %H2O = O2d =

O2w =

Percent moisture Oxygen diluent concentration (percent of effluent gas, dry basis) Oxygen diluent concentration (percent of effluent gas, wet basis)

M-1K H2O %H O

O O

O d w

d 2

2 2

2

100

, as adjusted1

1 Using a K-factor or other mathematical algorithm, per Appendix A, Section 6.5.7(a).

TABLE 32: CO2 FORMULA REFERENCE TABLE

Usage Moisture Basis Appropriate Formulas

(Part 75, Appendices F, G)

CO2 CEMS (O2 Analyzer)

WET F-14B and F-11

DRY F-14A and F-2

CO2 CEM (CO2 Analyzer)

WET F-11

DRY F-2

Fuel Sampling G-1 (and possibly G-2, G-3, G-5, G-6 and G-8)

Gas or Oil Flowmeter G-4

Overall Value from Multiple Flowmeter Systems

G-4A

TABLE 33: CO2 CONCENTRATION AND MASS EMISSION RATE FORMULAS


F-2 CO2

E K C Q H O

h hp hs 100

100 2%

Eh = K =

Chp =

Qhs =

%H2O=

Hourly CO2 mass emissions (tons/hr) 5.7 x 10-7 for CO2

((tons/scf)/percent CO2) Hourly average, CO2 concentration (percent CO2, dry basis) Hourly average volumetric flow rate (scfh, wet basis) Hourly average stack moisture content (percent by volume)




F-11 CO2

E K C Qh h h

Eh =

K =

Ch =

Qh =

Hourly CO2 mass emission rate (tons/hr) 5.7x10-7 for CO2

((tons/scf)/percent CO2) Hourly average CO2 concentration (percent CO2, wet basis) Hourly average volumetric flow rate (scfh, wet basis)

F-14A CO2C

CO F

F

O d

c d 2

2100 20 9

20 9

.

.

CO2d =

F = Fc =

20.9 = O2d =

Hourly average CO2 concentration (percent by volume, dry basis) Dry-basis F-factor (dscf/mmBtu) Carbon-based F-factor (scf CO2/mmBtu) Percentage of O2 in ambient air Hourly average O2 concentration (percent by volume, dry basis)

F-14B CO2C

CO F

F

H O Ow

c W2

2 2

100

20 9 20 9

100

100

.

. %

CO2w =

F = Fc =

20.9 =

Hourly average CO2 concentration (percent by volume, wet basis) Dry-basis F-factor (dscf/mmBtu) Carbon-based F-factor (scf CO2/mmBtu) Percentage of O2 in ambient air

O2W =

%H2O =

Hourly average O2 concentration (percent by volume, wet basis) Moisture content of gas in the stack (percent)

G-1 CO2M

W

MW MW W

MWCO

c O c

c 2

2

2000

WCO2 =

MWc = MWO2 = Wc =

CO2 emitted from combustion (tons/day) Molecular weight of carbon (12.0) Molecular weight of oxygen (32.0) Carbon burned (lb/day) determined using fuel sampling and analysis and fuel feed rates*

G-2 CO2M

W W MW

MW

A C WNCO CO

CO

c COAL 2 2

2

100 100

% %

WNCO2 =

WCO2 =

MWCO2 =

MWc =

Net CO2 mass emissions discharged to the atmosphere (tons/day) Daily CO2 mass emissions calculated by Equation G-1 (tons/day) Molecular weight of carbon dioxide (44.0) Molecular weight of carbon (12.0)

A% =

C% =

WCOAL =

Ash content of the coal sample (percent by weight) Carbon content of ash (percent by weight) Feed rate of coal from company records (tons/day)




G-3 CO2M

W WNCO CO2 2 99 .

WNCO2 = Net CO2 mass emissions from the combustion of coal discharged to the atmosphere (tons/day)

.99 = Average fraction of coal converted into CO2 upon combustion

WCO2 = Daily CO2 mass emissions from the combustion of coal calculated by Equation G-1 (tons/day)

G-4 CO2

W F H U MW

CO c f CO

2

2

2000

WCO2 = CO2 emitted from combustion (tons/hr)

Fc = Carbon-based F-factor, 1,040 scf/mmBtu for natural gas; 1,420 scf/mmBtu for crude, residual, or distillate oil and calculated according to the procedures in Section 3.3.5 of Appendix F to Part 75 for other gaseous fuels

H = Hourly heat input rate (mmBtu/hr) Uf = 1/385 scf CO2/lb-mole at 14.7 psi and

68EF MWCO2 = Molecular weight of carbon dioxide

(44.0)

G-4A CO2

CO

CO t

tunit

fuel fuel all fuels

unit

2

2

CO2unit = Unit CO2 mass emission rate (tons/hr)

CO2fuel = CO2 mass emission rate calculated using Equation G-4 for a single fuel (tons/hr)

tfuel = Fuel usage time tunit = Unit operating time

G-5 CO2M

SE W F MW

MWCO CaCO u CO

CaCO 2 3

2

3

SECO2 = CO2 emitted from sorbent (tons/day) WCaCO3 = Calcium carbonate used (tons/day) Fu = 1.00, the calcium to sulfur

stoichiometric ratio MWCO2 = Molecular weight of carbon dioxide

(44.0) MWCaCO3 = Molecular weight of calcium

carbonate (100.0)

G-6 CO2M

SE F W MW

MWCO u SO CO

SO 2

2

2 2000

2

SECO2 = CO2 emitted from sorbent (tons/day) MWCO2 = Molecular weight of carbon dioxide

(44.0) MWSO2 = Molecular weight of sulfur dioxide

(64.0) WSO2 = Sulfur dioxide removed (lb/day)

based on applicable procedures, methods, and equations in § 75.15

Fu = 1.00, the calcium to sulfur stoichiometric ratio




G-8 CO2M

22 COCOt SEWW

Wt

WCO2

SECO2

= Estimated total CO2 mass emissions (tons/day)

= CO2 emitted from fuel combustion (tons/day)

= CO2 emitted from sorbent (tons/day)

* See Appendix G, sections 2.1.1 through 2.1.3 ** For a unit linked to a common pipe with one additional fuel flowmeter system defined at the unit, a G-4A formula is reported to calculate the unit hourly CO2 rate, even though there is only a single fuel flowmeter defined at the unit. Because the fuel usage time may not be equal to the unit operating time, the hourly CO2 rate for the fuel may be different from the hourly CO2 rate for the unit. Formula G-4A is used to calculate the unit hourly CO2 rate.

TABLE 34: HEAT INPUT FORMULA REFERENCE TABLE

Usage Moisture Basis Appropriate Hourly Formulas (Part 75, Appendices D and F)

CEMS (O2 Analyzer) WET F-17

DRY F-18

CEMS (CO2 Analyzer) WET F-15

DRY F-16

Gas Fuel Flowmeter System D-6 (F-20)

Oil Fuel Flowmeter System (Mass)

D-8 (F-19)

Oil Fuel Flowmeter System (Volumetric) D-3 and D-8 (F-19) or F-19V

Overall Value from Multiple Fuel Flowmeter Systems

D-15A

Apportioned Value from Common Stack or Common Pipe

F-21A, F-21B, or F-21

Summed Value from Multiple Stacks F-21C

Summed Value from Unit F-25



TABLE 35: HEAT INPUT FORMULAS


D-15A HI

tHI =HI

irate-i

all- fuels rate-hr

HIrate-hr = Heat input rate from all fuels combusted during the hour (mmBtu/hr)

HIrate-i = Heat input rate for each type of gas or oil combusted during the hour (mmBtu/hr)

tu ti = Time each gas or oil fuel was combusted for the hour (fuel usage time) (fraction of an hour)

tu = Operating time of the unit

F-15 HI

100

%COx F

1 xQHI = 2w

c w

HI = Hourly heat input rate (mmBtu/hr)

Qw, Qh = Hourly average volumetric flow rate (scfh, wet basis)

Fc = Carbon-based F-factor (scf/mmBtu)

F = Dry basis F-factor (dscf/mmBtu)

%CO2w = Hourly concentration of CO2

(percent CO2, wet basis) %CO2d = Hourly concentration of CO2

(percent CO2 , dry basis) %O2w = Hourly concentration of O2

(percent O2, wet basis) %O2d = Hourly concentration of O2

(percent O2, dry basis) %H2O = Hourly average moisture of gas

in the stack (percent)

F-16 HI

100

%CO 100 F

% H O-100 xQHI = 2d

c

2 h

F-17 HI

20.9

]% O-% H O)[(20.9/100)(100 -x

F

1 xHI = Q 2w2

W

F-18 HI

20.9

)%O(20.9 -

100F

% H O)(100 -xQHI = 2d2

w

D-3 OILM

x DV=OIL oil-rateoilrate

OILrate = Mass rate of oil consumed per hr (lb/hr)

Voil-rate = Volume rate of oil consumed per hr, measured (scf/hr, gal/hr, barrels/hr, or m3/hr)

Doil = Density of oil, measured (lb/scf, lb/gal, lb/barrel, or lb/m3)

D-8** HI HIrate-oil = Hourly heat input rate from (F-19V) combustion of oil (mmBtu/hr)

OILrate = Rate of oil consumed (lb/hr for

10

GCVxOIL=HI 6

oil raterate-oil

Equation D-8 or gal/hr for Equation F-19V)

GCVoil = Gross calorific value of oil (Btu/lb for Equation D-8 or Btu/gal for Equation F-19V)

106 = Conversion of Btu to mmBtu




F-19 HI

10

GCVx= MHI 6

o oo

HIo =

Mo =

GCVo =

106 =

Hourly heat input rate from combustion of oil (mmBtu/hr) Mass rate of oil consumed per hour (lb/hr) Gross calorific value of oil (Btu/lb) Conversion of Btu to mmBtu

D-6 HI

10

x GCVGAS =HI 6

gasrate rate-gas

HIrate-gas,= HIg

GASrate,= Qg

GCVgas,= GCVg

106 =

Hourly heat input rate from combustion of gaseous fuel (mmBtu/hr) Average volumetric flow rate of fuel (100 scfh) Gross calorific value of gaseous fuel (Btu/100 scf) Conversion of Btu to mmBtu

F-20 HI

10

x GCV )(Q =HI 6

gg g

** For units required to monitor NOx mass emissions but not SO2 mass emissions, if there is a volumetric oil flowmeter, it is possible to use Equation D-8 on a volumetric basis, rather than a mass basis. If this option is used, it is represented as Equation F-19V in the monitoring plan.

TABLE 36: APPORTIONMENT AND SUMMATION FORMULAS


F-21A HI

tMW

MW t

t

t= HIHI ii

n

i=1

ii

i

CS CSi

HIi

HICS

MWi

ti

tCS

n

i

=

=

= =

=

=

=

Heat input rate for a unit (mmBtu/hr) Heat input rate at the common stack or pipe (mmBtu/hr) Gross electrical output (MWe) Operating time at a particular unit Operating time at common stack or pipe Total number of units using the common stack or pipe Designation of a particular unit

F-21B HI

tSF

SF t

t

t= HIHI ii

n

i=1

ii

i

CS CSi

HIi

HICS

n SFi

ti

tCS

=

=

= = =

=

Heat input rate for a unit (mmBtu/hr) Heat input rate at the common stack or pipe (mmBtu/hr) Number of stacks or pipes Gross steam load (flow) (lb/hr) Operating time at a particular unit Operating time at common stack or pipe

n

i

=

=

Total number of units using the common stack or pipe Designation of a particular unit




F-21C HI

t

tHI =HI

Unit

ss

n

s=1 Unit

HIUnit

HIs

tUnit

ts

s

n

=

=

= =

=

=

Heat input rate for a unit (mmBtu/hr) Heat input rate for each stack or duct (mmBtu/hr) Operating time for the unit Operating time for a particular stack or duct Designation of a particular stack or duct Total number stacks, ducts

F-21D HI

tFF

FF t

t

t= HIHI ii

n

i=1

ii

i

CP CPi

HIi

HICP

FFi

ti

tCP

=

=

=

=

=

Heat input rate for a unit (mmBtu/hr) Heat input rate at the common pipe (mmBtu/hr) Fuel flow rate to a particular unit (appropriate units) Operating time at a particular unit (hr) Operating time at common pipe (hr)

n

i

=

=

Total number of units using the common pipe Designation of a particular unit

F-25 HI

tHI =HI

uu

p

u=1 CS

HICS

HIu

p tu

=

=

= =

Hourly average heat input rate at the common stack (mmBtu/hr) Hourly average heat input rate for a unit (mmBtu/hr) Number of units Operating time at a particular

tCS

tCS

u

=

=

unit Operating time at common stack Designation of a particular unit



TABLE 37: NOX MASS EMISSIONS FORMULAS (LBS/HR)


F-24A NOX

x HI= ERE h(NOx)hNOx)h(

E(NOx)h =

K =

Chd =

Chw =

Qh =

%H2O =

HIh =

ER(NOx)h =

Hourly NOx mass emissions rate in lb/hr 1.194 x 10-7 for NOx

((lb/scf)/ppm) Hourly average, NOx

concentration (ppm (dry)) Hourly average, NOx

concentration, stack moisture basis (ppm (wet)) Hourly average volumetric flow rate (scfh) Hourly average stack moisture content (percent by volume) Hourly average heat input rate (mmBtu/hr) Hourly average NOx emission rate (lb/mmBtu)

F-26A NOX

hhwNOx h QCKE )(

F-26B NOX

100

% H O)(100 -xx Q= K x CE

2 hhNOx h d)(

TABLE 38: MISCELLANEOUS FORMULA CODES

Code Parameter Description

N-GAS FGAS Net or total gas fuel flow rate (100 scfh)

N-OIL FOIL Net or total oil fuel flow rate (scf/hr, gal/hr, barrels/hr, m3/hr, or lb/hr)

X-FL FLOW Average hourly stack flow rate (scfh). (To calculate the average of two or more primary flow monitors, for example, two ultrasonic monitors in an X-pattern)

T-FL FLOW Total stack flow rate (scfh)

SS-1A SO2 Total hourly SO2 mass emissions from the affected unit(s) in a subtractive stack configuration (lb/hr)

SS-1B SO2 Hourly SO2 mass emissions from a particular affected unit in a subtractive stack configuration (lb/hr)

SS-2A NOX Total hourly NOx mass emissions from the affected unit(s) in a subtractive stack configuration (lb/hr)

SS-2B NOX Hourly NOx mass emissions from a particular affected unit in a subtractive stack configuration (lb/hr). (Apportioned by gross load)

SS-2C NOX Hourly NOx mass emissions from a particular affected unit in a subtractive stack configuration (lb/hr). (Apportioned by steam load)

SS-3A HIT Total hourly heat input for the affected unit(s) in a subtractive stack configuration (mmBtu)

SS-3B HI Hourly heat input rate for a particular affected unit in a subtractive stack configuration (mmBtu/hr)



Code Parameter Description

NS-1 NOXR Hourly NOx apportionment for NOx affected units in a subtractive stack configuration (lb/mmBtu)

NS-2 NOXR Hourly NOx apportionment for NOx affected units using simple NOx

apportionment (lb/mmBtu)

TABLE 39: REPRESENTATIONS FOR ELECTRONIC REPORTING

Operation Recommended Representation Example

Addition + MW_1 + MW_2

Subtraction - (100 - %H2O)

Multiplication * Cd * Fd

Division / %CO2/100

Exponential Power ** 1.66 x 10-7 = 1.66 * 10 ** -7

Subscript Underscore MW1 = MW_1

Fraction of Heat Input from Fuel X_<fuel> X_oil

Gross Electrical Output MW_<unit> MW_1

Gross Steam Load (Flow) SF_<unit> SF_1

Hourly Emissions E_h E_h

Operating Time T_<unit/stack> T_CS1

12.0 SPAN VALUES

TABLE 40: COMPONENT TYPE CODES AND DESCRIPTIONS FOR MONITOR SPAN

Code Description

CO2 CO2 Concentration (percent)

FLOW Stack Flow

NOX NOx Concentration (ppm)

O2 O2 Concentration (percent)

SO2 SO2 Concentration (ppm)



TABLE 41: PROVISION FOR CALCULATING MAXIMUM POTENTIAL CONCENTRATIONS (MPC)/ MAXIMUM EXPECTED CONCENTRATION (MEC)/ MAXIMUM POTENTIAL FLOW RATE (MPF)

CODES AND DESCRIPTIONS

Code Description

F Formula (low and high-scale SO2, flow rate, and low-scale NOx only)

HD Historical Data

TR Test Results

TB Table of Constants from Part 75 or Default Values from Part 75 (e.g., 800 ppm NOx for coal-firing)

OL Other Limit

GS Low Scale Default for SO2 for Gas Units

PL NOx MEC Based on Permit Limit

ME NOx MPC Based on Manufacturer's Estimate of Uncontrolled Emissions

TABLE 42: FLOW SPAN CALIBRATION UNITS OF MEASURE

Code Description

ACFH Actual Cubic Feet of Stack Flow per Hour

ACFM Actual Cubic Feet of Stack Flow per Minute

AFPM Actual Feet of Stack Flow per Minute

AMSEC Actual Meters of Stack Flow per Second

AFSEC Actual Feet of Stack Flow per Second

INH2O Inches of Water

KACFH Thousand Actual Cubic Feet of Stack Flow per Hour

KACFM Thousand Actual Cubic Feet of Stack Flow per Minute

KAFPM Thousand Actual Feet of Stack Flow per Minute

KSCFH Thousand Standard Cubic Feet of Stack Flow per Hour

KSCFM Thousand Standard Cubic Feet of Stack Flow per Minute

KSFPM Thousand Standard Feet of Stack Flow per Minute

MACFH Million Actual Cubic Feet of Stack Flow per Hour

MSCFH Million Standard Cubic Feet of Stack Flow per Hour



Code Description

SCFH Standard Cubic Feet of Stack Flow per Hour

SCFM Standard Cubic Feet of Stack Flow per Minute

SFPM Standard Feet of Stack Flow per Minute

SMSEC Standard Meters of Stack Flow per Second

13. RECTANGULAR DUCT WAF

TABLE 43: WAF METHOD CODE AND DESCRIPTIONS

Code Description

FT Full Test (CTM-041 §§8.1 and 8.2)

AT Abbreviated Test (CTM-041 §8.4.1)

DF Default Value (CTM-041 §8.4.2)

14. UNIT/STACK/PIPE LOAD OR OPERATING LEVEL INFORMATION

TABLE 44: MAXIMUM LOAD VALUE CODES AND DESCRIPTIONS

Code Description

MW Electrical Capacity (in megawatts)

KLBHR Steam (load) Mass Rate (in units of 1000 lbs/hr)

MMBTUHR BTUs of Steam Produced (in mmBtu/hr)

Note: This field is left blank for units that do not produce electrical or steam load.



15. MONITORING DEFAULTS

TABLE 45: PARAMETER CODES AND DESCRIPTIONS FOR MONITORING DEFAULT

Category Parameter

Code Description

Diluent Cap CO2N CO2 Diluent Cap.

O2X O2 Diluent Cap.

Low Mass Emissions Parameters (§§75.19 and 75.81(b))

CO2R CO2 Default Emission Factor, from Table 45 or Fuel and Unit-Specific CO2 Default Emission Factor, for Combustion of "Other" Gaseous Fuel (tons/mmBtu).

NOXR NOx Default Emission Factor, from Table 42 or Fuel and Unit-Specific NOx Emission Rate1 (lb/mmBtu).

SO2R SO2 Default Emission Factor, from Table 43 or Fuel and Unit-Specific SO2 Default Emission Factor Calculated Using Equation D-1h, either (1) for combustion of "other" gaseous fuel; or (2) for fuel oil combustion, based on the maximum weight percent sulfur in the operating permit (lb/mmBtu).

MHHI Maximum Rated Hourly Heat Input Rate (mmBtu/hr).

Missing Data Values

or

Maximum Values for Unmonitored Bypass Stack and Emergency Fuels

H2ON Minimum Potential Percent Moisture.

H2OX Maximum Potential Percent Moisture.

CO2X Maximum Percent CO2.

O2N Minimum Potential Percent Oxygen.

SO2X Fuel-Specific Maximum Potential SO2 Concentration (ppm).

NOCX Fuel-Specific Maximum Potential (MPC) or Maximum Expected NOx Concentration (ppm) for all hours or controlled hours. For Appendix E missing data purposes, report the MPC used to calculate the Maximum NOx Emission Rate for each fuel curve and, if applicable, for Emergency fuel.

NORX Maximum NOx Emission Rate (MER) and Fuel-Specific Maximum Potential or Maximum Expected NOx Emission Rate (lb/mmBtu) for all hours or controlled hours. For Appendix E missing data purposes, an MER must be determined for each fuel curve and, if applicable, for Emergency fuel.

FLOX Fuel-Specific Maximum Potential Flow Rate (scfh).

Moisture Default Parameter H2O Hourly Percent Moisture Content (%H2O).

BWA Moisture Fraction in Ambient Air.



Category Parameter

Code Description

SO2 Emission Rate Parameter for Use in Formula F-23

SO2R SO2 Generic Default Emission Factor for Pipeline Natural Gas; or

Fuel and Unit-Specific Default Emission Factor Calculated Using Equation D-1h for combustion of "other" gaseous fuel; or

Emission Factor approved by petition for a very low sulfur solid or liquid fuel (or combination of fuels) per §75.11 (e).

Other Parameters (subject to EPA approval of petition)

MNHI Minimum Heat Input Rate (mmBtu/hr).

MNNX Minimum NOx Emission Rate (lb/mmBtu).

Other Parameters (not subject to EPA approval of petition)

MNOF Minimum Oil Flow Rate.

MNGF Minimum Gas Flow Rate.

1 "NOXR" is reported in the following cases: (1) for fuel-and-unit specific NOx emission rates obtained by testing; and (2) for the maximum potential NOx emission rate, if that value is reported in the interval from the first hour of use of the LME methodology until the hour of completion of fuel-and-unit specific NOx emission rate testing (see §75.19 (a)(4)).

TABLE 46: FUEL-SPECIFIC MINIMUM DEFAULT MOISTURE VALUES

FOR SO2, NOX, CO2, AND HEAT INPUT RATE CALCULATIONS

Fuel Minimum Moisture

Default Value

Anthracite Coal 3.0%

Bituminous Coal 6.0%

Sub-bituminous Coal 8.0%

Lignite Coal 11.0%

Wood 13.0%

Natural Gas (boilers only) 14.0%



TABLE 47: FUEL-SPECIFIC MAXIMUM DEFAULT MOISTURE VALUES

FOR NOX EMISSION RATE CALCULATIONS

Fuel Maximum Moisture

Default Value

Anthracite Coal 5.0%

Bituminous Coal 8.0%

Sub-bituminous Coal 12.0%

Lignite Coal 13.0%

Wood 15.0%

Natural Gas (boilers only) 18.0%

TABLE 48: NOX EMISSION FACTORS (LB/MMBTU) FOR LOW MASS EMISSIONS UNITS

Boiler Type Fuel Type NOx Emission Factors

Turbine Natural Gas 0.7

Oil 1.2

Boiler Natural Gas 1.5

Oil 2.0

TABLE 49: SO2 EMISSION FACTORS (LB/MMBTU) FOR LOW MASS EMISSIONS UNITS

Fuel Type SO2 Emission Factors

Pipeline Natural Gas (as defined in §72.2) 0.0006

Natural Gas 0.06

Residual Oil or Other Oil 2.10

Diesel Fuel 0.50

TABLE 50: CO2 EMISSION FACTORS (TON/MMBTU) FOR LOW MASS EMISSIONS UNITS

Fuel Type CO2 Emission Factors

Natural Gas 0.059

Oil 0.081



TABLE 51: UNITS OF MEASURE CODES BY PARAMETER

Units of Measure Code Description Parameter Code

PCT Percent CO2N, CO2X, H2O, H2ON, H2OX, O2N, O2X

LBMMBTU Pounds per Million Btu MNNX, NOXR, SO2R, NORX

MMBTUHR Million Btu per Hour MNHI, MHHI

TNMMBTU Tons per Million Btu CO2R

SCFH Standard Cubic Feet per Hour MNOF, FLOX,

PPM Parts per million SO2X, NOCX

GALHR Gallons of Oil per Hour MNOF

BBLHR Barrels of Oil per Hour MNOF

M3HR Cubic Meters of Oil per Hour MNOF

LBHR Pounds of Oil per Hour MNOF

HSCF Hundred SCF of Gas per Hour MNGF

TABLE 52: DEFAULT PURPOSE CODES AND DESCRIPTIONS

Code Description Parameter Code

DC Diluent Cap CO2N, O2X

DM Default Minimum Fuel Flow Rate MNGF, MNOF

F23 SO2 Emission Rate Default for Use in Equation F-23 SO2R

LM Low Mass Emissions Unit Default (§§75.19 and 75.81(b)) CO2R, SO2R, NOXR, MHHI

MD Missing Data, Unmonitored Bypass Stack, or Emergency Fuel

CO2X, FLOX, H2ON, H2OX, MNHI, MNNX, NOCX, NORX, O2N, SO2X

PM Primary Measurement Methodology BWA, H2O


Type Code Description

LME Defaults (§75.19)


BUT Butane (if measured as a gas)


COG Coke Oven Gas




DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas


NNG Natural Gas

OGS Other Gas

OIL Residual Oil

OOL Other Oil

PDG Producer Gas


PRG Process Gas

PRP Propane (if measured as a gas)

RFG Refinery Gas


Moisture ANT Anthracite Coal

BT Bituminous Coal


LIG Lignite

NNG Natural Gas (including Pipeline Natural Gas)

PNG Pipeline Natural Gas

SUB Sub-bituminous Coal

W Wood

SO2 Emission Rate Default for Use in Equation F-23

NNG Natural Gas

PNG Pipeline Natural Gas

OGS Other Gas

* or MIX *With an approved petition, any liquid or solid fuel type that qualifies as very low sulfur fuel, or a mixture of such fuels. See fuel code list in UNIT FUEL DATA

Fuel-Specific CEMS Missing Data



C Coal

CDG Coal-Derived Gas

COG Coke Oven Gas





DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas


MIX Co-Fired Fuels

NNG Natural Gas

OGS Other Gas

OIL Residual Oil

OOL Other Oil


PDG Producer Gas


PRG Process Gas


PRS Process Sludge

PTC Petroleum Coke

R Refuse

RFG Refinery Gas


TDF Tire-Derived Fuel

W Wood

WL Waste Liquid

Fuel-Specific MPC/MER or MEC/MCR Reporting During Bypass Stack Operating Hours



C Coal

CDG Coal-Derived Gas

COG Coke Oven Gas


DGG Digester Gas

DSL Diesel Oil

LFG Landfill Gas


NNG Natural Gas




OGS Other Gas

OIL Residual Oil

OOL Other Oil


PDG Producer Gas


PRG Process Gas


PRS Process Sludge

PTC Petroleum Coke

R Refuse

RFG Refinery Gas


TDF Tire-Derived Fuel

W Wood

WL Waste Liquid

TABLE 54: OPERATING CONDITION CODES AND DESCRIPTIONS

Operating Condition Code Description

A Any Hour

C Controlled Hour

B Base Load Hour (LME units)

P Peak Load Hour (LME units)

U Uncontrolled Hour



TABLE 55: DEFAULT SOURCE CODES AND DESCRIPTIONS

Default Source Code Source of Value Description Parameter

APP* Approved (Petition) MNNX, SO2R, MNHI, H2O, MHHI

DATA** Historical or Other Relevant Data O2N, O2X, CO2X, H2ON, H2OX, FLOX, SO2X, NOCX, NORX, NOXR, MNOF, MNGF, BWA

PERM Maximum Weight Percent Sulfur in Fuel Oil, as Specified by Operating Permit (for LME)

SO2R, NORX, NOCX

TEST Unit/Stack Testing NOXR, FLOX, SO2X, NOCX, NORX

SAMP Fuel Sampling SO2R, CO2R, SO2X

CONT Contract Maximum SO2R

DEF Default Value from Part 75 CO2R, NOXR, CO2N, O2X, SO2R, H2ON, H2OX, SO2X, NOCX, NORX, H2O

MAXD Maximum Value Based on Design or Nameplate Capacity

MHHI, NORX, NOCX

* "APP" is reported if a source has an approved petition to use a site-specific SO2 emission factor for very low sulfur solid or liquid fuels.

** "DATA" is reported when a source is reporting the maximum potential NOx emission rate in the interval from the first hour of use of the LME methodology until the hour of completion of fuel-and-unit specific NOx emission rate testing (see §75.19 (a)(4)).

16.0 QUALIFICATIONS

TABLE 56: QUALIFICATION TYPE CODES AND DESCRIPTIONS

Category Code Description

Gas-Fired GF Gas-Fired Qualification

Low Mass Emitter LMEA Low Mass Emitter Qualification (Annual) -- Required when reporting on a year-round basis

LMES Low Mass Emitter Qualification (Ozone Season) -- Required when subject to an Ozone-Season NOx program

Peaking PK Peaking Unit Qualification (Annual)

SK Peaking Unit Qualification for Ozone Season (applies exclusively to sources that report on an ozone season-only basis)



Category Code Description

QA Test Exemption PRATA1 Single Load RATA Qualification by petition approval

PRATA2 Two Load RATA Qualification by petition approval

COMPLEX Exemption from Flow-to-Load Testing Due to Complex Configuration

LOWSULF SO2 RATA Exemption for a Source Combusting Only Very Low Sulfur Fuel

TABLE 57: QUALIFICATION DATA TYPE CODE AND DESCRIPTIONS

Code Description

A Actual Percent Capacity Factor or Fuel Usage

P Projected Capacity Factor or Fuel Usage

D 720 Hours of Unit Operating Data (gas-fired only)


Documents

Monitoring Plan XML File Codes...Monitoring Plan XML File Codes Tableof Contents. ... Table 57: Qualification Data Type Code and Descriptions ..... 42 MP XML File Codes May 24, 2012